In the past, it has been recognized that heaters may be useful in assisting hydrocarbon production from underground formations. Some of these heaters have been installed at the bottom of the well and the heater provides a fixed heat output. However, if the fluid flow is interrupted for any reason then heat generated by the heater is not adequately removed, so the temperature of the heater rises until a catastrophic failure of the heater (i.e., burnout) occurs. For example, U.S. Pat. No. 3,410,347 to Triplett, teaches using a burner as a means of producing heat at a remote underground location to stimulate hydrocarbon production from the well. However, the heater temperature produced by the Triplet burner is a function of the fuel flow rate, the air flowrate, fuel to air ratio, the burner pressure, the fuel atomization efficiency at the elevated downhole pressures, heat transfer surface area, heat transfer coefficients and fluid throughput through the heater. In spite of these factors which would greatly affect the safe and reliable operation of the burner, no control system is taught or even proposed by Triplett.
U.S. Pat. Nos. 2,484,063 and 2,500,305 to Ackley include the use of a current controller for the purpose of controlling downhole temperatures. Ackley teaches a device used to apply heat to air or steam which are used to deliver heat to the reservoir. Although Ackley suggests monitoring the downhole temperature, Ackley does not teach use of an adequate control system for controlling the temperature of the heater.
My own patent U.S. Pat. No. 5,120,935 discloses a heater for the purpose of heating solvents which are injected into the formation for the specific purpose of removing plugging wax deposits. The treatment time and cost of operating such a heater is directly related to the throughput and outlet temperature. Higher fluid throughput allows shorter treatment times so that the capital cost of the equipment can be spread over more treatments (wells). Higher throughput can also allow higher bottom hole injection pressures to be achieved with beneficial consequences on the effectiveness of the stimulation. For example, if an oil well has multiple producing zones, then any production zones that have been damaged or plugged by waxy solids may be at a higher fluid pressure than the adjacent depleted zones, so higher injection pressures may be necessary to achieve fluid inflow into the damaged zones.
The injection of fluid into a well is typically characterized by varying injection pressures and varying flowrates. These variations in flowrate and pressure arise due to a number of factors. The maximum allowable injection pressure is usually limited by physical constraints, such as the burst strength of the tubing or casing and the fracture pressure in the reservoir. If the injection pressure approaches one of these constraints the flowrate must be reduced. During the process of fluid injection into the well the near wellbore area becomes "charged" with fluid and the injection pressure required to achieve a constant flowrate increases. Offsetting this trend, is the removal of formation damage which facilitates fluid movement away from the near well bore area and tends to reduce the fluid injection pressure. The injection fluid is typically pumped from the surface using a pump which is driven by a truck engine or the like. Such truck engines will likely have other simultaneous loads, such as hydraulic subsystems (i.e., to operate a blow out preventer or B.O.P) which affect the engine speed and the amount of power available to drive the above-grade pump. Variations in hydraulic load can cause flow rate variations.
As the flowrate changes, the heater must respond in a timely way to maintain an outlet temperature within a desired range (deadband) around an optimal temperature or setpoint. The worst case scenario may be when fluid injection is suddenly interrupted due to a failure of the above-grade pump or a leak in the tubing. In this case, the temperature in the heater can rise very rapidly or "ballistically" because the injection fluid does not carry the heat away from the heater. Thus, to achieve a controlled temperature at the outlet of the heater, it is necessary to have a fast response control system to adjust the power output to the heater. Furthermore, in the worst case scenario described above, the control system must recognize a problem and respond by shutting off the power to the heater quickly enough to avoid dangerous overheating.
Smaller and more compact heaters (such as shown in my U.S. Pat. No. 5,120,935) allow higher throughputs without excessive pressure drop and also facilitate equipment handling and transport. For example, throughput of the heater can be doubled (at the same pressure drop) by reducing heater length by a factor of four. However, this doubling of throughput will increase the required power output in the heater by a factor of two and therefore the power output per unit volume is increased by a factor of eight and the ballistic rate of temperature increase will be eight times faster. Therefore to maintain adequate control, the control system response times have to be eight times faster. Thus, a shorter and more high-powered heater requires an ever faster control system response.
Mechanical thermostat type control devices as taught in the prior art cannot respond quickly enough to keep the temperature within a useful control range for high power heaters. For example, to control the heater outlet temperature within 10.degree. C. in the heater described in my own prior patent U.S. Pat. No. 5,120,935, the overall control system (including temperature sensors and power controls) should have a response time of less than 1.5 seconds since the ballistic heating rate of the heater in a "no-flow" condition is about 7.degree. C. per second. Such a response time can be achieved with mechanical thermostatic type controls. However, to double the power output, the response time of the overall control system should be less than 200 milliseconds (=1.5/8 seconds) to achieve control within the same deadband.